U.S. patent number 7,013,740 [Application Number 10/737,856] was granted by the patent office on 2006-03-21 for two-phase steam measurement system.
This patent grant is currently assigned to Invensys Systems, Inc.. Invention is credited to Robert E. Dutton, Wade M. Mattar.
United States Patent |
7,013,740 |
Dutton , et al. |
March 21, 2006 |
Two-phase steam measurement system
Abstract
A steam measurement system includes a Coriolis flowmeter
associated with a vibratable flowtube to receive a flow of wet
steam. A first sensor is associated with the flowtube to relay
information about a motion of the flowtube by way of a first sensor
signal. A second sensor determines a property of the flow and
relays the property by way of a second sensor signal. A computing
device receives the first and second sensor signals and is
configured to calculate a steam quality of the flow from the first
and second sensor signals. The computing device also may calculate
the total heat energy flow rate of the flow. Other implementations
may include a full or partial separator to separate the flow of wet
steam into a substantially gas flow and a substantially liquid flow
and a second Coriolis meter.
Inventors: |
Dutton; Robert E. (Louisville,
CO), Mattar; Wade M. (Wrentham, MA) |
Assignee: |
Invensys Systems, Inc.
(Foxboro, MA)
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Family
ID: |
33423652 |
Appl.
No.: |
10/737,856 |
Filed: |
December 18, 2003 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20040221660 A1 |
Nov 11, 2004 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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60467553 |
May 5, 2003 |
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Current U.S.
Class: |
73/861.354 |
Current CPC
Class: |
G01F
1/74 (20130101); G01F 1/8468 (20130101); G01F
15/024 (20130101); G01F 15/046 (20130101); G01F
15/08 (20130101); G01N 9/002 (20130101) |
Current International
Class: |
G01F
1/84 (20060101) |
Field of
Search: |
;73/861.04,861.06,861.355,861.356,354 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Other References
Wenger, Alfred P., "Vibrating Fluid Densimeters: A Solution to the
Viscosity Problem," IEEE Transactions on Industrial Electronics and
Control Instrumentation, vol. 1 IECI-27, No. 3, pp. 247-253. cited
by other.
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Primary Examiner: Lefkowitz; Edward
Assistant Examiner: Thompson; Jewel V.
Attorney, Agent or Firm: Fish & Richardson P.C.
Parent Case Text
CLAIM OF PRIORITY
This application claims priority under 35 USC .sctn. 119(e) to U.S.
patent application Ser. No. 60/467,553, filed on May 5, 2003, the
entire contents of which are hereby incorporated by reference.
Claims
What is claimed is:
1. A steam measurement system comprising: a Coriolis flowtube to
receive a flow of wet steam, wherein a bulk density of the flow is
determined based on a motion of the Coriolis flowtube; a sensor to
determine a property of the flow of wet steam; a computing device
configured to calculate a steam quality of the flow from the bulk
density and the property; a steam generator to generate the flow of
wet steam; a transport element to deliver the flow of wet steam to
the Coriolis flowtube; and an injection well connected to the
Coriolis flowtube to receive the flow of wet steam from the
Coriolis flowtube.
2. The steam measurement system of claim 1 wherein the property is
a temperature of the flow and the sensor is a temperature
sensor.
3. The steam measurement system of claim 2 wherein the temperature
sensor is connected to the outside of the flowtube.
4. The steam measurement system of claim 2 wherein the temperature
sensor is inserted into the flow of wet steam.
5. The steam measurement system of claim 1 wherein the property is
a pressure of the flow and the sensor is a pressure sensor.
6. The steam measurement system of claim 1 wherein, to calculate
the steam quality, the computing device is configured to calculate
a density of a vapor phase of the flow from the property and to
calculate a density of a liquid phase of the flow from the
property.
7. The steam measurement system of claim 6 wherein the computing
device includes a memory storing a steam table, the computing
device configured to use the steam table to calculate the density
of the vapor phase from the property and the density of the liquid
phase from the property.
8. The steam measurement system of claim 6 wherein, to calculate
the steam quality, the computing device is configured to use the
bulk density, the density of the liquid phase, and the density of
the gas phase to solve the following equation for the steam quality
.times..times..times..times..times..times..times..times..times.
##EQU00007##
9. The steam measurement system of claim 1 wherein the computing
device comprises a Coriolis transmitter.
10. The steam measurement system of claim 1 wherein the computing
device comprises a flow computer.
11. A steam measurement system comprising: a Coriolis flowtube to
receive a flow of wet steam, wherein a bulk density and a bulk mass
flow rate of the flow is determined based on a motion of the
Coriolis flowtube; a sensor to determine a property of the flow of
wet steam; a computing device configured to calculate a steam
quality of the flow from the bulk density and the property, and is
configured to calculate a heat energy flow rate of the flow from
the steam quality and the bulk mass flow rate.
12. The steam measurement system of claim 11 wherein, to calculate
the heat energy flow rate, the computing device is configured to
calculate an enthalpy of the vapor phase of the flow from the
property and to calculate an enthalpy of the liquid phase of the
flow from the property.
13. The steam measurement system of claim 12 wherein, to calculate
the heat energy flow rate, the computing device is configured to
use the bulk mass flow rate m, the enthalpy of the liquid phase
h.sub.f, the enthalpy of the gas phase h.sub.g, and the steam
quality x to solve the following equation for the heat energy flow
rate H.sub.total: H.sub.total=mh.sub.gx+mh.sub.f(1-x).
14. A method comprising: passing a flow of wet steam through a
vibrating flowtube associated with a Coriolis flowmeter, wherein
the Coriolis flowmeter determines the bulk density of the flow of
wet steam; obtaining a temperature or a pressure of the flow of wet
steam; calculating a steam quality of the flow from the bulk
density and the temperature or pressure; calculating the bulk mass
flow rate of the flow of wet steam; and calculating a heat energy
flow rate of the flow from the steam quality, the bulk mass flow
rate, and the temperature or pressure.
15. The method of claim 14 wherein calculating the steam quality
comprises: calculating a density of a vapor phase of the flow from
the temperature or pressure; and calculating a density of a liquid
phase of the flow from the temperature or pressure.
16. The method of claim 15 wherein calculating the steam quality
comprises solving the following equation for the steam quality x:
.times..times..times..times..times..times. ##EQU00008##
17. The method of claim 14 wherein calculating the heat energy flow
rate comprises: calculating an enthalpy of the vapor phase of the
flow from the temperature or pressure obtained from the second
sensor; and calculating an enthalpy of the liquid phase of the flow
from the temperature or pressure obtained from the second
sensor.
18. The method of claim 14 wherein calculating the heat energy flow
rate comprises solving the following equation for the heat energy
flow rate H.sub.total: H.sub.total=mh.sub.gx+mh.sub.f(1-x) where m
is the bulk mass flow rate, h.sub.f is the enthalpy of the liquid
phase, h.sub.g is the enthalpy of the gas phase, and x is the steam
quality.
19. A steam measurement system comprising: a separator to separate
a flow of wet steam into a substantially gas flow and a
substantially liquid flow; a first Coriolis flowtube to receive the
substantially gas flow, wherein a bulk densisty of the
substantially gas flow is determined based on a motion of the first
Coriolis flowtube; a second Coriolis flowtube to receive the
substantially liquid flow, wherein a bulk density of the
substantially liquid flow is determined based on a motion of the
second Coriolis flowtube; a sensor to detect a temperature or
pressure of the substantially gas flow or the substantially liquid
flow; and a computing device to calculate a total steam quality of
the flow of wet steam from the bulk density of the substantially
gas flow, the bulk density of the substantially liquid flow, and
the temperature or pressure.
20. The steam measurement system of claim 19 wherein the sensor is
a temperature sensor.
21. The steam measurement system of claim 20 wherein the
temperature sensor is connected to the outside of the first or
second Coriolis flowtube.
22. The steam measurement system of claim 20 wherein the
temperature sensor is inserted into the substantially gas or
substantially liquid flow.
23. The steam measurement system of claim 19 wherein the sensor is
a pressure sensor.
24. The steam measurement system of claim 19 wherein, to calculate
the steam quality, the computing device is configured to use the
temperature or pressure to calculate a density of a vapor phase of
the substantially gas flow; a density of a liquid phase of the
substantially gas flow; a density of a vapor phase of the
substantially liquid flow; and a density of a liquid phase of the
substantially liquid flow.
25. The steam measurement system of claim 24 wherein the computing
device includes a memory storing a steam table, the computer
configured to use the steam table to calculate the density of a
vapor phase of the substantially gas flow; the density of a liquid
phase of the substantially gas flow; the density of a vapor phase
of the substantially liquid flow; and the density of a liquid phase
of the substantially liquid flow.
26. The steam measurement system of claim 19 wherein a bulk mass
flowrate of the substantially gas flow is determined based on
motion information of the first Coriolis flowtube, a bulk mass
flowrate of the substantially liquid flow is determined based on
motion information of the second Coriolis flowtube, and the
computing device is configured to calculate a heat energy flow rate
of the flow from the steam quality, the bulk mass flowrate of the
substantially liquid flow, the bulk mass flowrate of the
substantially gas flow, and the temperature or pressure.
27. The steam measurement system of claim 26 wherein, to calculate
the heat energy flow rate, the computing device is configured to
use the temperature or pressure to calculate an enthalpy of the
vapor phase of the substantially gas flow; to calculate an enthalpy
of the liquid phase of the substantially gas flow; to calculate an
enthalpy of the vapor phase of the substantially liquid flow; and
to calculate an enthalpy of the liquid phase of the substantially
liquid flow.
28. The steam measurement system of claim 19 wherein the computing
device comprises a Coriolis flowmeter transmitter.
29. The steam measurement system of claim 19 wherein the computing
device comprises a flow computer.
30. The steam measurement system of claim 19 further comprising: a
steam generator to generate the flow of wet steam; a transport
element to deliver the flow of wet steam to the separator; and an
injection well connected to the first and second Coriolis flowtubes
to receive the substantially gas and substantially liquid flows
from the first and second Coriolis flowtubes.
31. A Coriolis transmitter for use with a steam measurement system
that includes a Coriolis flowtube to receive a flow of wet steam; a
first sensor associated with the flowtube to relay information
about a motion of the flowtube by way of a first sensor signal; and
a second sensor to determine a property of the flow and to relay
the property by way of a second sensor signal, the Coriolis
transmitter comprising: a processing device to receive the first
and second sensor signals, the processing device configured to
calculate a steam quality of the flow from the first and second
sensor signals.
32. The transmitter of claim 31 wherein the processing device is
configured to calculate a heat energy flow rate of the flow from
the steam quality and the first and second sensor signals.
33. The transmitter of claim 32 wherein, to calculate the heat
energy flow rate, the processing device is configured to calculate
an enthalpy of the vapor phase of the flow from the property and to
calculate an enthalpy of the liquid phase of the flow from the
property.
34. The transmitter of claim 33 wherein, to calculate the heat
energy flow rate, the processing device is configured to calculate
a bulk mass flowrate of the flow from the first sensor signal.
35. The transmitter of claim 34 wherein, to calculate the heat
energy flow rate, the processing device is configured to use the
bulk mass flow rate m, the entalpy of the liquid phase h.sub.f, the
enthalpy of the gas phase h.sub.g, and the steam quality x to solve
the following equation for the heat energy flow rate H.sub.total:
H.sub.total=mh.sub.gx+mh.sub.f(1-x).
Description
TECHNICAL FIELD
This description relates to two-phase steam measurements.
BACKGROUND
There are instances in which it is beneficial to measure various
properties of saturated steam. One such instance is the extraction
of crude oil from the ground. Heavy, tar-like oil lies in geologic
formations below the earth's surface in large quantities. In order
to extract this commercially valuable resource, wet, saturated
steam may be produced at a steam generator or other steam-producing
device and transported through various transport elements (such as,
for example, flow lines, manifolds, valves, tees, and fittings) to
one or more injection wells at the site(s) of the heavy, tar-like
oil. At the injection wells, the steam may be injected into the
heavy oil formations to thin the crude oil and facilitate pumping
it to the surface.
SUMMARY
In one aspect, a steam measurement system is provided. The steam
measurement system includes a Coriolis flowtube to receive a flow
of wet steam. A bulk density of the flow is determined based on a
motion of the Coriolis flowtube. A sensor determines a property of
the flow of wet steam. A computing device calculates a steam
quality of the flow from the bulk density and the property.
Implementations of this aspect may include one or more of the
following features. For example, the property may be a temperature
of the flow, with the sensor being a temperature sensor. The
temperature sensor may be connected to the outside of the flowtube
or the temperature sensor may be inserted into the flow of wet
steam. The property may be a pressure of the flow, with the sensor
being a pressure sensor.
To calculate the steam quality, the computing device may be
configured to calculate a density of a vapor phase of the flow from
the property and to calculate a density of a liquid phase of the
flow from the property. The computing device may include a memory
storing a steam table and be configured to use the steam table to
calculate the density of the vapor phase from the property and the
density of the liquid phase from the property. The computing device
may be configured to calculate the steam quality using the bulk
density, the density of the liquid phase, and the density of the
gas phase to by solving the following equation for the steam
quality x: .times..times..times..times..times..times.
##EQU00001##
The computing device also may be configured to determine a bulk
mass flow rate of the flow based on a motion of the Coriolis
flowtube and may be configured to calculate a heat energy flow rate
of the flow from the steam quality and the bulk mass flow rate. To
calculate the heat energy flow rate, the computing device may be
configured to calculate an enthalpy of the vapor phase of the flow
from the property, to calculate an enthalpy of the liquid phase of
the flow from the property. The computing device may be configured
to calculate the heat energy flow rate using the bulk mass flow
rate m, the enthalpy of the liquid phase h.sub.f, the enthalpy of
the gas phase h.sub.g, and the steam quality x by solving the
following equation for the heat energy flow rate H.sub.total:
H.sub.total=mh.sub.gx+mh.sub.f(1-x).
The computing device may be a Coriolis flowmeter transmitter or a
flow computer.
The steam measurement system also may include a steam generator to
generate the flow of wet steam; a transport element to deliver the
flow of wet steam to the Coriolis flowtube; and an injection well
connected to the Coriolis flowtube to receive the flow of wet steam
from the Coriolis flowtube.
In another aspect, a method is provided that includes passing a
flow of wet steam through a vibrating flowtube associated with a
Coriolis flowmeter, wherein the Coriolis flowmetere determines the
bulk density of the flow of wet steam; obtaining a temperature or a
pressure of the flow of wet steam; and calculating a steam quality
of the flow from the bulk density and the temperature or
pressure.
Implementations of this aspect may include one or more of the
following features. For example, calculating the steam quality may
include calculating a density of a vapor phase of the flow from the
temperature or pressure; and calculating a density of a liquid
phase of the flow from the temperature or pressure. The steam
quality may be calculated by solving the following equation for the
steam quality x: .times..times..times..times..times..times.
##EQU00002##
The bulk mass flow rate of the flow may be calculated and a heat
energy flow rate of the flow also may be calculated from the steam
quality, the bulk mass flow rate, and the temperature or pressure.
Calculating the heat energy flow rate may include calculating an
enthalpy of the vapor phase of the flow from the temperature or
pressure; and calculating an enthalpy of the liquid phase of the
flow from the temperature or pressure. The heat energy flow rate
H.sub.total may be calculated by solving the following equation:
H.sub.total=mh.sub.gx+mh.sub.f(1-x), where m is the bulk mass flow
rate, h.sub.f is the enthalpy of the liquid phase, h.sub.g is the
enthalpy of the gas phase, and x is the steam quality.
In another aspect, a steam measurement system including a separator
is provided. The separator separates a flow of wet steam into a
substantially gas flow and a substantially liquid flow. A first
Coriolis flowtube receives the substantially gas flow and a bulk
density of the substantially gas flow is calculated based on a
motion of the first Coriolis flowtube. A second Coriolis flowtube
receives the substantially liquid flow and a bulk density of the
substantially liquid flow is determined based on a motion of the
second Coriolis flowtube. A sensor detects a temperature or
pressure of the substantially gas flow or the substantially liquid
flow. A computing device is configured to calculate a total steam
quality of the flow of wet steam from the bulk density of the
substantially gas flow, the bulk density of the substantially
liquid flow, and the temperature or pressure.
Implementations of this aspect may include one or more of the
following features. For example, the sensor may be a temperature
sensor. The temperature sensor may be connected to the outside of
the first or second Coriolis flowtube or inserted into the
substantially gas or substantially liquid flow. The sensor may be a
pressure sensor.
To calculate the steam quality, the computing device may be
configured to use the temperature or pressure to calculate a
density of a vapor phase of the substantially gas flow; a density
of a liquid phase of the substantially gas flow; a density of a
vapor phase of the substantially liquid flow; and a density of a
liquid phase of the substantially liquid flow. The computing device
may include a memory storing a steam table and be configured to use
the steam table to calculate the density of a vapor phase of the
substantially gas flow; the density of a liquid phase of the
substantially gas flow; the density of a vapor phase of the
substantially liquid flow; and the density of a liquid phase of the
substantially liquid flow.
A bulk mass flowrate of the substantially gas flow may be
determined based on motion information of the first Coriolis
flowtube and a bulk mass flowrate of the substantially liquid flow
may be determined based on motion information of the second
Coriolis flowtube. The computing device may be configured to
calculate a heat energy flow rate of the flow from the steam
quality, the bulk mass flowrate of the substantially liquid flow,
the bulk mass flowrate of the substantially gas flow, and the
temperature or pressure.
To calculate the heat energy flow rate, the computing device may be
configured to use the temperature or pressure to calculate an
enthalpy of the vapor phase of the substantially gas flow; to
calculate an enthalpy of the liquid phase of the substantially gas
flow; to calculate an enthalpy of the vapor phase of the
substantially liquid flow; and to calculate an enthalpy of the
liquid phase of the substantially liquid flow. The computing device
may be a Coriolis flowmeter transmitter or a flow computer.
The steam measurement system also may include a steam generator to
generate the flow of wet steam; a transport element to deliver the
flow of wet steam to the separator; and an injection well connected
to the first and second Coriolis flowtubes to receive the
substantially gas and substantially liquid flows from the first and
second Coriolis flowtubes.
In another aspect, a Coriolis transmitter for use with a steam
measurement system includes a Coriolis flowtube to receive a flow
of wet steam; a first sensor associated with the flowtube to relay
information about a motion of the flowtube by way of a first sensor
signal; and a second sensor to determine a property of the flow and
to relay the property by way of a second sensor signal. The
Coriolis transmitter includes a processing device to receive the
first and second sensor signals. The processing device is
configured to calculate a steam quality of the flow from the first
and second sensor signals.
Implementations of this aspect may include one or more of the
following features. For example, the processing device also may be
configured to calculate a heat energy flow rate of the flow from
the steam quality and the first and second sensor signals. To
calculate the heat energy flow rate, the processing device may be
configured to calculate an enthalpy of the vapor phase of the flow
from the property, to calculate an enthalpy of the liquid phase of
the flow from the property, and to calculate a bulk mass flowrate
of the flow from the first sensor signal. The processing device may
be configured to calculate the heat energy flow rate using the bulk
mass flow rate m, the enthalpy of the liquid phase h.sub.f, the
enthalpy of the gas phase h.sub.g, and the steam quality x by
solving the following equation for the heat energy flow rate
H.sub.total: H.sub.total=mh.sub.gx+mh.sub.f(1-x).
The details of one or more implementations are set forth in the
accompanying drawings and the description below. Other features
will be apparent from the description and drawings, and from the
claims.
DESCRIPTION OF DRAWINGS
FIG. 1 is a block diagram of a two-phase steam measurement system
used at injection wells.
FIG. 2 is a diagram illustrating a temperature-pressure
relationship of water.
FIG. 3 is an excerpt from a saturated steam temperature table.
FIG. 4 is a block diagram of a Coriolis meter being used in a steam
measurement system.
FIG. 5 is a block diagram of a Coriolis meter and a temperature
transmitter being used in a steam measurement system.
FIG. 6 is a block diagram of a Coriolis meter and a pressure
transmitter being used in a steam measurement system.
FIG. 7 is a flowchart describing a process for determining steam
quality measurements.
FIG. 8 is a flowchart describing a process for determining heat
energy flow rate measurements.
FIG. 9 is a block diagram of a steam measurement system used in
conjunction with a gas/liquid separator.
FIG. 10 is a flowchart describing a process for accounting for
dissolved solids when determining steam quality measurements.
DETAILED DESCRIPTION
FIG. 1 is a block diagram of a steam generation and injection
system 100 that includes a two-phase steam measurement system.
System 100 includes a steam generator 120, transport elements 130
connecting the output of steam generator 120 to injection wells
160, and meters 140 along with corresponding transmitters 150
located near the injection wells. In general, feedwater 110 is
input to steam generator 120, which turns feedwater 110 into steam.
The steam is transported to the injection wells 160 by transport
elements 130, e.g. flowlines, manifolds, valves and fittings.
Meters 140, along with the corresponding transmitters 150, are used
to measure properties of the steam near injection wells 160.
Feedwater 110 may be distilled to remove any solids or other
impurities. However, using distilled water may be expensive or
impractical. Alternatively, oil companies may produce steam in
steam generators rather than other steam-producing equipment, such
as boilers, so that, for example, enough liquid leaves the steam
generator to carry away any dissolved solids that may exist in the
feedwater used by the steam generator in generating the steam. This
eliminates the expensive proposition of using distilled water as
the feedwater. Thus, the steam produced and transported is
typically "wet steam," i.e., water with a phase relationship such
that liquid is contained in some form or amount within a vapor of
the water.
FIG. 2 is a phase diagram 200 illustrating the two-phase nature of
a pure substance, in this case water. As shown in FIG. 2, a
temperature and/or pressure of water determines state
characteristics of the water. For example, the water might be in a
compressed liquid state 210, but as heat is added, the temperature
of the compressed liquid rises until it reaches the saturation
liquid line 211. If this is done at atmospheric pressure then the
temperature is 212.degree. F. If heat is continuously added to the
water at atmospheric pressure, some of the liquid turns to vapor.
If enough heat is added to convert half, by mass, of the liquid to
vapor for example, then the steam is said to have 50% quality. As
we continue to add heat to the steam, all of the liquid turns to
vapor at the saturation vapor line 213. At this point the
temperature is still 212.degree. F. and the pressure is still one
atmosphere absolute. If heat is further applied to this steam, the
temperature and pressure will rise into the superheated vapor state
214, where the temperature and pressure are independent of one
another.
Thus the term wet/saturated steam is a thermodynamic term, meaning
water that is not superheated nor compressed liquid, and is below
the critical point of 705.5.degree. F. and 3208 psia. Saturated
steam can be from 0% to 100% in "steam quality," as discussed
below, and its temperature and pressure are related in the
Two-Phase Region 212 of the phase diagram 200. For instance,
212.degree. F. is tied to atmospheric pressure of 14.7 psia, as is
327.8.degree. F. is tied to 100 psia. Steam tables have been
developed to give the properties of saturated steam (e.g., density
and heat energy of the phases) at a given temperature and
corresponding pressure.
FIG. 3 is an excerpt from a saturated steam temperature table. As
just described, such a table relates various properties associated
with water at various conditions. Specifically, the table of FIG. 3
illustrates various properties of wet/saturated steam at various
temperatures and pressures. The properties include the specific
volume of the components of the wet steam (specific volume
represents the space occupied per unit mass of a substance, and is
the mathematical inverse of density), the enthalpy of the
components of the wet steam (i.e., a term that represents the total
energy content of the wet steam; it expresses the internal energy
and flow work, or the total potential energy and kinetic energy
contained within a substance, and may be expressed in, for example,
British thermal units per pound (mass), or BTU/lbm), and the
entropy of the components of the wet steam (representing, in this
case, energy of the wet steam that may be lost due to
transportation of the wet steam).
Wet steam that leaves generator 120 is said to have a particular
"steam quality," which refers to the percentage of the steam, by
mass, that is in the vapor phase. For example, wet steam that is
80% vapor may be said to have an 80% steam quality. The remainder
of the saturated steam is in the liquid phase, and it carries away
the dissolved solids so that, for example, the heat exchange tubes
of steam generator 120 do not become coated and fail.
As described previously, this wet/saturated steam leaves steam
generator 120 and flows through transport elements 130 on its way
to injection wells 160, as shown in FIG. 1. These transport
elements 130 may lie over various topographical formations. For
example, some transport elements 130 may traverse hills and have a
high elevation, whereas other transport elements 130 may lie in
valleys and have a low elevation. As the steam flow splits and
divides and traverses the various transport elements 130 in their
various settings, the liquid does not always remain with the vapor
in the same ratio that it left generator 120. As a result, the
quality of the steam flows that reach injection wells 160 may be
significantly different from one another and from the quality of
the steam when exiting the steam generators, and may range anywhere
from 0% to 100%. Capacitance probes, dual orifice plates, and
vibrating tube densitometers, for example, have been used in the
past to try to measure this steam quality, with very limited
success.
Knowledge of the steam quality at the injection wells 160, as
opposed to at the generator 120, may be important to operators of
injection wells 160. For example, the operators may want to know
the steam quality at injection wells 160 because the steam quality
often is related to the amount of commercially-usable oil that is
extracted. In particular, when more vapor is contained within the
wet steam (i.e., when the steam quality is high), more energy may
be transferred into injection wells 160. Therefore, operators of
injection wells 160 may seek to optimize steam flow into injection
wells 160, so as to extract a maximized amount of oil relative to a
minimized amount of wet steam injected into wells 160.
This optimization process may include, for example, using flowtubes
140 and corresponding transmitters 150 to detect a low steam
quality at a particular injection well and fixing a flow fault that
is associated with transport elements 130 (and/or with steam
generator 120) associated with that well. The optimization process
also may include, as another example, adjusting various transport
elements 130 to ensure that the various injection wells 160 do not
receive significantly different steam qualities.
Flowtubes 140 and corresponding transmitters 150 are, respectively,
Coriolis flowtubes and Coriolis transmitters. A Coriolis flowtube
and Coriolis transmitter are collectively referred to as a Coriolis
flowmeter. A Coriolis flowmeter is a type of flowmeter, where
flowmeters, generally speaking, provide information about materials
being transferred through a conduit or flowtube. For example,
density meters, or densitometers, provide a measurement of the
density of material flowing through a conduit. Additionally, mass
flowmeters provide a measurement of the mass of material being
transferred through a conduit by, for example, deriving the mass
flow measurement from an earlier density measurement and a
volumetric flow measurement. Other mass flowmeters may calculate
mass flow directly.
Coriolis-type flowmeter systems calculate density and mass flow
using the Coriolis effect, in which material flowing through a
rotating conduit becomes a radially-traveling mass that is affected
by a Coriolis force and therefore experiences an acceleration. Many
Coriolis mass flowmeter systems induce a Coriolis force by
sinusoidally oscillating a conduit about a pivot axis orthogonal to
the length of the conduit. In such mass flowmeters, the Coriolis
reaction force experienced by the traveling fluid mass is
transferred to the conduit itself and is manifested as a deflection
or offset of the conduit in the direction of the Coriolis force
vector in the plane of rotation.
In general, the term flowtube as used herein refers to the flowtube
and any associated mechanical parts, drivers, and sensors, while
the term "transmitter" refers to the electronics for producing
drive signals to control the flowtube oscillations and calculating
the properties of the material flowing through the flowtube based
on signals received from the sensors. Additionally, the term
Coriolis flowmeter generally refers to a combination of flowtube
and transmitter.
U.S. Pat. No. 6,311,136 and U.S. Pat. No. 6,507,791, which are
hereby incorporated by reference, disclose the use of a digital
flowmeter system and related technology. Such digital flowmeter
systems are very precise in their measurements, with little or
negligible noise, and are capable of enabling a wide range of
positive and negative gains at the driver circuitry for driving the
conduit. Such digital flowmeter systems are thus advantageous in a
variety of settings. For example, U.S. Pat. No. 6,505,519 discloses
the use of a wide gain range, and/or the use of negative gain, to
prevent stalling and to more accurately exercise control of the
flowtube, even during difficult conditions such as the two-phase
flow of wet/saturated steam.
A digital transmitter exchanges sensor and drive signals with its
associated conduit or flowtube, so as to both sense an oscillation
of the flowtube, and to drive the oscillation of the flowtube
accordingly. By quickly and accurately determining the sensor and
drive signals, the digital transmitter may provide for fast and
accurate operation of the flowtube in determining characteristics
of the flow including a mass flow rate of the flow. A digital
transmitter may be implemented using one or more of, for example, a
processor, a field-programmable gate array, an ASIC, other
programmable logic or gate arrays, or programmable logic with a
processor core.
Although digital flowmeter systems are discussed above, it should
be understood that analog Coriolis flowmeter systems also exist.
Although such analog flowmeter systems may be prone to typical
shortcomings of analog circuitry, e.g., low precision and high
noise measurements relative to digital flowmeters, they also may be
compatible with the various techniques and implementations
discussed herein. Thus, the terms "flowtube," "transmitter," and
"flowmeter" should not be understood as being limited to digital
systems.
FIGS. 4 6 illustrate various configurations in which a Coriolis
flowmeter and other sensors may be used to measure steam quality
and/or other properties of wet steam, for example, near an
injection well. In general, by measuring the bulk density of the
wet steam using the Coriolis flowmeter along with a measurement of
the wet steam's temperature or pressure, the steam quality and
other properties of the wet steam may be determined.
FIG. 4 is a block diagram illustrating a Coriolis flowmeter system
used in a steam measurement system 400. System 400 includes a
Coriolis flowtube 410 that receives wet steam from an input
transport element 420. After flowing through the flowtube 410, the
wet steam exits through an output transport element 430. As the wet
steam flows through the flowtube 410, various measurements of the
flowtube 410 are taken so that a Coriolis transmitter 440 can
determine the bulk density of the wet steam. In addition, a
temperature sensor is associated with the Coriolis flowtube 410 and
coupled to the flowtube 410 to obtain flowtube temperature data,
which is indicative of the temperature of the wet steam. For
example, a resistance temperature device (RTD) may be coupled to
the flowtube 410 and used to obtain flowtube temperature data.
The temperature sensor may be one that is provided with Coriolis
flowtube 410 to correct for temperature changes of the flowtube
410. Specifically, in some Coriolis flowmeters, a temperature
sensor is already associated with the Coriolis flowtube because a
temperature of the flowtube and/or the material being transported
may affect, for example, a stiffness of the flowtube (and thereby a
resonant frequency of oscillation of the flowtube, which, in turn,
may affect a density and/or mass flow measurement obtained by the
flowmeter). Alternatively, the temperature sensor coupled to the
flowtube may be used solely for a temperature measurement related
to the measurement of properties of the wet steam.
By using the temperature of the flowtube 410 (and, indirectly, of
the wet steam) thus obtained, along with the information contained
in a steam table such as that shown in FIG. 3 and the bulk density
of the wet steam as measured by the Coriolis flowmeter, the steam
quality and other properties of the flow may be calculated in the
manner(s) described below with respect to FIG. 7. These
calculations may be performed by transmitter 440 and/or may be
performed by an associated flow computer 440, such as might be used
to measure the oil and oil-mixtures produced. Such flow computers
may be used in conjunction with multiple wells and/or multiple
steam quality calculations at those (or other) wells. The
calculations also may be performed, for example, by a programmed
control system.
FIG. 5 is a block diagram of a Coriolis flowtube 510 and a separate
temperature transmitter 550 used in a steam measurement system 500.
System 500 is similar to system 400 except for a separate
temperature transmitter/sensor 550 is used in addition, or as an
alternative, to a temperature sensor associated with Coriolis
flowtube 510. Temperature transmitter 550 may include a thermal
well or temperature probe inserted into the flowing material (i.e.,
wet steam) itself. Temperature transmitter 550, particularly if
calibrated before being put into the flow, may provide a more
accurate measure of the temperature of the wet steam (particularly
because it is directly measuring the wet steam itself, and is not
indirectly determining the temperature of the wet steam based on a
temperature of the flowtube obtained by an external sensor, such as
in FIG. 4).
FIG. 6 is a block diagram of a Coriolis flowtube 610 and a pressure
transmitter 650 used in a steam measurement system 600. System 600
is similar to system 500 except for a pressure transmitter/sensor
650 is used in place of a temperature transmitter/sensor 550. As
described above, temperature and pressure are tied together for wet
steam. Thus, either pressure or temperature provides the
information necessary to calculate the steam quality or other
properties as described below.
FIG. 7 is a flowchart illustrating a process for determining steam
quality measurements using a system such as one of those shown in
FIGS. 4 6. A temperature or pressure reading of the steam is
obtained (710) from a temperature or pressure sensor/transmitter,
such as sensor 550 or 650. The temperature or pressure is then used
to calculate the density of the liquid phase (720) and the density
of the vapor phase (730).
The densities may be calculated by storing a steam table, for
example, in a transmitter and looking up the appropriate property
in the steam table. For instance, referring to the steam table of
FIG. 3, if the temperature sensor associated with Coriolis meter
410 or temperature transmitter 550 indicates 360.degree. F. (or if
absolute pressure transmitter 650 indicates 153 psia) then the
density of the liquid phase (as the inverse of specific volume
v.sub.f) is calculated from the steam table of FIG. 3 as:
.times..times..times..times. ##EQU00003## and the density of the
vapor phase (as the inverse of specific volume v.sub.g) is
calculated from the steam table of FIG. 3 as:
.times..times..times..times. ##EQU00004## Alternatively, the steam
table information may be stored algorithmically and the algorithm
may be used to obtain the densities.
The bulk density of the wet steam flowing through the flowtube is
obtained (740). The densities of the vapor and liquid phases, along
with the bulk density are then used to calculate the steam quality
(750). The following equation expresses the relationship between
the bulk density, vapor density, liquid density, and steam quality
x. .times..times..times..times..times..times. ##EQU00005##
The steam quality thus can be determined by solving for x, given
the bulk density, liquid density, and vapor density To continue the
example from above, if the bulk density is, for example, 0.5
lb/ft.sup.3, then the steam quality is calculated as: ##EQU00006##
x=0.67 or 67% steam quality.
In short, a Coriolis flowmeter (and/or a temperature/pressure
sensor) can be used with a table such as the one of FIG. 3 to
determine a density of each of the gas and liquid phases of the wet
steam. Since the Coriolis meter may measure the bulk density, the
steam quality may be deduced in the manner just described.
FIG. 8 is a flowchart describing a process 800 for determining heat
energy flow rate measurements using the steam quality and the mass
flow rate. Process 800 may be implemented using, for example, one
of the configurations illustrated in FIGS. 4 6.
As described above, a Coriolis flowmeter may be used to measure the
bulk mass flow rate of the two-phase steam. Using the bulk mass
flow rate, the steam quality, and information about the wet steam
obtainable from a steam table, the heat energy flow rate of steam
flowing into a well 160 may be calculated. Such a heat energy flow
rate measurement, along with the mass flow rate, may provide an
operator of the injection wells 160 with additional information
helpful in optimizing the steam-injection process.
Accordingly, referring to FIG. 8, the bulk mass flow rate of the
steam is obtained by a Coriolis flowmeter (810). The steam quality
is calculated (820) as described above using a reading from a
temperature or pressure sensor/transmitter, such as sensor 550 or
650, and a steam table such as the one shown in FIG. 3. The
temperature or pressure is then used to calculate the enthalpy of
the liquid phase (830) and the enthalpy of the vapor phase (840).
Like the densities for the steam quality calculation, the
enthalpies may be calculated by storing a steam table, for example,
in a transmitter and looking up the appropriate property in the
steam table. For instance, referring to the steam table of FIG. 3,
if the temperature sensor associated with Coriolis flowtube 410 or
temperature transmitter 550 indicates 360.degree. F. (or if
absolute pressure transmitter 650 indicates 153 psia) then the
enthalpy of the liquid phase is calculated from the steam table of
FIG. 3 as 332.3 BTU/lbm and the enthalpy of the vapor phase is
calculated as 1194.4 BTU/lbm. Alternatively, the steam table
information may be stored algorithmically and the algorithm may be
used to obtain the enthalpies.
The enthalpies of the vapor and liquid phases, along with the bulk
mass flow rate, and the steam quality are then used to calculate
the heat energy flow rate of the steam (850). The following
equation expresses the relationship between the heat energy flow
rate H.sub.total, bulk mass flow rate m, the vapor enthalpy
h.sub.g, liquid enthalpy h.sub.f, and steam quality x.
H.sub.total=mh.sub.gx+mh.sub.f(1-x)
Using the 360.degree. F. example discussed above with 67% quality,
and assuming a mass flow, m, of 20,000 lb/day:
H.sub.total=20,000(1194.4)0.67+20,000(332.3)(1-0.67)
H.sub.total=18.2 million Btu per day.
FIG. 9 is a block diagram of a system 900 that includes a steam
measurement system used in conjunction with a gas/liquid separator.
In system 900, the two-phase, wet steam is separated to some extent
by a separator 920. Such a configuration may be desirable in some
circumstances. For instance, some Coriolis flowmeters do not
accurately measure density and mass flow if the gas fraction (GVF
or Gas Volume Fraction) is above a particular amount, for example,
about 30%; or below a particular amount, for example, about 90%. An
implementation using a partial or full separator also may allow a
use of a temperature/pressure transmitter directly on a
substantially pure gas phase of the two-phase steam.
Wet steam is input to a full or partial separator 920 by an input
transport element 910. Separator 920 fully or partially separates
the wet steam into a substantially gas flow and a substantially
liquid flow. The substantially gas flow is output through a gas
transport element 930, while the substantially liquid flow is
output through a liquid transport element 940. A temperature or
pressure transmitter 990 may be connected to gas transport element
930 for measuring the temperature or pressure of the substantially
gas flow, which will be equal to the temperature or pressure of the
substantially liquid flow. A Coriolis flowtube 950a and associated
transmitter 960a also is connected to gas transport element 930.
Similarly, a Coriolis flowtube 950b and associated transmitter 960b
is connected to liquid transport element 940. After flowing through
Coriolis flowtubes 950a and 950b, respectively, the substantially
gas flow and the substantially liquid flow combine and are output
through output transport element 980.
Coriolis flowtube 950a and transmitter 960a therefore can detect
the bulk density of the substantially gas flow, while the Coriolis
flowtube 950b and transmitter 960b can detect the bulk density of
the substantially liquid flow. Coriolis transmitter 960a transmits
the bulk density of the substantially gas flow to flow computer
970. Coriolis transmitter 960b also transmits the bulk density of
the substantially liquid flow to flow computer 970. The mass flow
rates of the substantially gas and liquid flows also may be
measured by the respective Coriolis flowtube 950a or 950b and
transmitter 960a and 960b. With the densities of the gas and liquid
flows, and the temperature or pressures of the two flows, flow
computer 970 can calculate the total steam quality, the total mass
flow rate, and the total heat energy flow rate of the flow exiting
through output transport element 980. To calculate the total mass
flow rate, flow computer 970 adds the mass flow rates of each flow.
To calculate the total steam quality and the total heat energy flow
rate, flow computer 970 calculates the steam quality and heat
energy flow rate of each flow, in a manner similar to that
described above, and sums the values.
FIG. 10 is a flowchart describing a process for accounting for
dissolved solids when determining steam quality measurements. This
may be particularly useful when calculating steam quality
measurements for low steam quality flows, such as, for example,
flows that have 10 20% steam quality. The feed water used in steam
generator 120 may be high in total dissolved solids (TDS), if it
is, for example, pre-processed, produced water or ground water. As
it passes through generator 120 and most of it turns to vapor, the
remaining liquid becomes concentrated with TDS. For example, if the
feed water is 2000 ppm TDS, and the generator puts out 80% quality
steam, the liquid phase will concentrate to 10,000 ppm TDS. This
will result in the liquid phase being denser by 0.62 lb/ft.sup.3
than the steam tables indicate. The steam table of FIG. 3 is based
on pure, distilled water, but a Coriolis flowmeter will measure the
bulk density of the vapor and the liquid with the TDS.
Moreover, as the two-phase steam loses pressure from, for example,
friction in the flow lines and pressure drops from valves and
chokes, more of the liquid turns to vapor, concentrating the TDS in
the liquid phase even further.
The steam quality actually increases with pressure drop, and with a
constant enthalpy process this can be calculated by:
H.sub.1=H.sub.2
(1-x.sub.1)H.sub.1f+x.sub.1H.sub.1g=(1-x.sub.2)H.sub.2f+x.sub.2H.sub.2g.
Where x.sub.1 is the quality before, and x.sub.2 is the quality
after, and the various "H" terms are the enthalpies of the liquid
and vapor (f and g, respectively) before and after. If we take our
previous example of 80% quality steam at, say 440.degree. F. (381.5
psia); and this drops to 360.degree. F. (153 psia), then:
(1-0.8)419+0.8(1204.4)=(1-x.sub.2)332.3+1194.4x.sub.2 x.sub.2=0.83
or 83% quality. In this case, the liquid phase has concentrated the
TDS by another 3% so the resulting TDS is now 10,309.3 ppm, or 0.64
lb/ft.sup.3 denser than the steam tables.
In the case of FIG. 10, then, the TDS of the feed water, the steam
quality at the generator, the temperature (or pressure) at the
generator, and the temperature (or pressure) at the point of
measurement are used to detect a measurement (e.g., density)
difference, if any, from the steam table of FIG. 3. Such a
difference can then be used to obtain accurate indications of steam
quality and/or heat energy flow rate of the wet steam. The
generator data can be communicated digitally to all measurement
points as the generator conditions change, or can be manually input
into the transmitter and/or flow computer.
In performing the above-described measurements and calculations, a
static mixer may be placed upstream of the Coriolis flowmeter(s)
(e.g., in FIG. 1). Such a static mixer may be instrumental in
avoiding calculation issues related to, for example, slip
velocities of the vapor and liquid (e.g., the velocities of the
vapor and liquid relative to one another within the flow), and/or
to different flow regimes of the flow (e.g., the manner in which
the vapor and liquid are contained and flowing within the wet
steam. For example, in one regime, the liquid may flow around a
perimeter of the transport element (e.g., tube), with the vapor in
the middle. In another regime, the vapor may be dispersed as
bubbles within the wet steam liquid phase). Alternatively, the
static mixer may be avoided by accounting for these and other
parameters during calculations, perhaps using examples and
techniques discussed in, for example, the U.S. Provisional
Application No. 60/452,934, titled Multiphase Coriolis Flowmeter
and filed Mar. 10, 2003, which is hereby incorporated by
reference.
A number of implementations have been described. Nevertheless, it
will be understood that various modifications may be made.
* * * * *